Method and apparatus for multilateral junction

ABSTRACT

A junction for the intersection of a main borehole and a lateral borehole includes a main tubular having a main window with a ramp aligned with the main window and a lateral tubular adapted to be telescopingly received within the main tubular and having a lateral window. The main tubular and lateral tubular each have an orientation surface. The lateral tubular has a first position with one end partially disposed within the main tubular. The lateral tubular is telescoped into the main tubular with the end of the lateral tubular engaging the ramp which guides the end of the lateral tubular through the main window and into the lateral bore. The orientation surfaces engage to orient the lateral window with the main window and form a common opening between the tubulars.

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application is a continuation of prior U.S. application Ser.No. 09/992,219, filed Nov. 6, 2001, which claims the benefit of 35U.S.C. § 119(e) of U.S. Provisional Application No. 60/247,295, filedNov. 10, 2000 and entitled “Method And Apparatus For MultilateralCompletions,” hereby incorporated herein by reference for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable.

BACKGROUND OF THE INVENTION

[0003] 1. Field of the Invention

[0004] The present invention relates generally to a method and apparatusfor the completion of multilateral wells, that is, when one or morelateral wells are drilled from a primary well bore, and moreparticularly to a new and improved method and apparatus for a junctionbetween the primary well bore and a lateral well bore.

[0005] 2. Background of the Invention

[0006] Multiple lateral bores are typically drilled and extended from aprimary or main well bore. The main well bore can be vertical, deviated,or horizontal. Multilateral technology can be applied to both new andexisting wells, and provides operators several benefits and economicadvantages over drilling entirely new wells from the surface. Forexample, multilateral technology can allow isolated pockets ofhydrocarbons, which might otherwise be left in the ground, to be tapped.In addition, multilateral technology allows the improvement of reservoirproduction, increases the volume of recoverable reserves, and enhancesthe economics of marginal pay zones. By using multilateral technology,multiple reservoirs can be produced simultaneously, thus facilitatingheavy oil production. Thin production intervals that might beuneconomical to produce alone become economical when produced togetherwith multilateral technology. Consequently, it has become a commonpractice to drill deviated, and sometimes horizontal, lateral boreholesfrom a primary wellbore in order to increase production from a well.

[0007] In addition to production cost savings, development costs alsodecrease through the use of existing infrastructure, such as surfaceequipment and the well bore. Multilateral technology expands platformcapabilities where space is limited, and allows more well bores to beadded to produce a reservoir without requiring additional drilling andproduction space on the platform. In addition, by sidetracking depletedformations or completions, the life of existing wells can be extended.Finally, multilateral completions accommodate more wells with fewerfootprints, making them ideal for environmentally sensitive orchallenging areas.

[0008] The primary wellbore may be sidetracked to produce the lateralborehole into another production zone. Further, a lateral wellbore maybe sidetracked into a common production zone. In sidetracking, awhipstock and mill assembly is used to create a window in the wall ofthe casing of a wellbore. The lateral wellbore is then drilled throughthis window out into the formation where new or additional productioncan be obtained.

[0009] One of the objectives of a multilateral well is containment ofthe surrounding formation. Production from a lateral borehole can bedifficult if the lateral borehole is drilled through a loose orunconsolidated formation. If the lateral borehole is drilled through anunstable or unconsolidated formation, the formation will tend to caveinto the borehole. The formation can also slough off, causingdeleterious debris to mix with the production fluids. Thus, it ispreferred to contain the formation to prevent cave-ins and slough-offs.

[0010] Formations that contain a significant amount of shale can be aparticular problem. If the bore surfaces at and near the junction arenot covered with a liner, chips and aggregate in this area tend to bedrawn into the produced fluids and foul the production. Unfortunately,lining the bore surfaces near the junction can be complex and timeconsuming. Various devices have been proposed to provide a junction atthe interface of the primary and lateral wellbores.

[0011] There have been attempts to use a perforated insert through thewindow to allow production from both the primary bore and lateral borewhile reducing contamination from chips and aggregate. The perforationsare aligned with the primary bore and fluid from the primary bore passesthrough the perforations. Unfortunately, the perforations tend to becomeclogged by the chips and aggregate and allow the chips and aggregate tocontaminate the product, thereby reducing the effectiveness of this typeof insert. Also, the use of a perforated insert hinders the ability toreenter the main bore below the junction.

[0012] The junction of the lateral borehole with the primary wellbore isusually ragged and rough as a result of the milling of the windowthrough the casing to drill the lateral borehole. It is particularlydifficult to seal around the window which is of a peculiar shape and hasa jagged edge around its periphery.

[0013] A large area is exposed to the formations when the window is cutin the casing. A tie-back assembly may be disposed adjacent the junctionof the lateral borehole and primary wellbore. See for example U.S. Pat.No. 5,680,901. The tieback assembly and liner limit the exposure of theformation through the window cut in the casing.

[0014] U.S. Pat. No. 5,875,847 discloses a multilateral sealing devicecomprising a casing tool having a lateral root premachined and pluggedwith cement. A profile receives a whipstock for the drilling of thelateral bore hole through the lateral root and cement plug. A lateralliner is then inserted and sealed within the lateral root.

[0015] TAML (Technology Advancement Multi-Lateral) defines six levelsfor a multi-lateral junction for a lateral borehole. For example, levelthree merely includes a junction with the main casing and a linerextending into the lateral borehole without cementing or sealing thejunction. If the liner is merely cemented at the junction, it is a levelfour since cement is not acceptable as a seal. Level four simplyincludes cement around the junction. Level five requires pressureintegrity at the junction.

[0016] Prior art multilateral wells are sealed with cement using amethod well-known to those with skill in the art and describedhereinafter.

[0017] Level five includes seals used to achieve pressure integrityaround the junction. For example, in level five, separate tubularsextend through the main borehole and through the lateral borehole. Apacker is placed around the upper ends of these tubulars to pack offwith the casing of the cased main borehole. The lower end of the tubularextending through the main tubular includes a packer for sealing withthe main tubular below the junction, and the lower end of the othertubular extending through the lateral borehole seals with an outertubular in the lateral borehole below the junction. The lateral boreholepreferably has been previously cased so that a seal can be set with thattubular extending into the lateral borehole. Since there are separatetubulars and both bores are now packed off, there can be independentproduction from each bore without commingling. The pair of tubularsabove the junction may extend all the way to the surface, or one wellmay be produced through a production pipe extending to the surface andthe other well may be produced through the annulus formed by the casingand the production pipe extending to the surface.

[0018] Where the formation pressure is substantially the same in the payzones being produced by the main and lateral boreholes, the hydrocarbonsfrom the main and lateral boreholes may be commingled. However, it issometimes desirable to separate production so that each well can beindependently controlled, such as where the pay zone pressures aredifferent. In that case, separate tubulars are used to produce theindividual wells, as previously described in a level five junction, orone well may be plugged off if necessary. Whether production iscommingled or independent has no bearing on how a multilateral well isclassified.

[0019] If the formation is a solid formation, the lateral borehole, forexample, need not even include a casing or liner and may be producedopen hole. If the lateral borehole is unconsolidated or unstable andwould tend to cave in, the lateral borehole would be cased off orinclude a liner to contain the formation. For example, it is common inthe prior art to run and set a liner in the lateral borehole with theliner extending from the flowbore of the casing and down into thelateral borehole. Cement is then pumped down through the cased mainborehole, across the junction into the lateral borehole below thejunction, and into the lateral borehole both inside and outside theliner. Then, the bore of the cased main borehole is cleaned out bydrilling out the cement, including milling off that portion of the linerextending into the bore of the cased main borehole, leaving an exposedend of the liner at the junction which extends into the lateralborehole. The liner is then cleaned out giving access to both the mainand lateral boreholes. This procedure is tedious and includes theproblem of the drill tending to enter the liner as it removes the cementand liner end from the main borehole. This method is also problematicbecause the cement acts as both the junction and the seal. The cement issubject to failure due to limitations in the cement material itself orthe ability to place the cement successfully at the junction. Moreparticularly, under downhole conditions, cement can fail bydeteriorating to such an extent that the seal begins to leak thuscontaminating the production fluids.

[0020] An alternative to the above-described method is described inpending U.S. patent application Ser. No. 09/480,073, filed Jan. 10, 2000and entitled “Lateral Well Tie-Back Methods and Apparatus.” A lateralwell tie-back apparatus and method is used to help ensure adequate flowand production from a lateral bore.

[0021] There are a variety of additional configurations that arepossible when performing multilateral completions. For example, U.S.Pat. No. 4,807,704 discloses a system for completing multiple lateralwellbores using a dual packer and a deflective guide member. U.S. Pat.No. 2,797,893 discloses a method for completing lateral wells using aflexible liner and deflecting tool. U.S. Pat. No. 3,330,349 discloses amandrel for guiding and completing multiple lateral wells. U.S. Pat.Nos. 4,396,075, 4,415,205, 4,444,276, and 4,573,541 all relate generallyto methods and devices for multilateral completion using a template ortube guide head. For a more comprehensive list of patents, U.S. Pat. No.6,012,526 details these configurations and presents a patent literaturehistory of the well-recognized problem of multilateral wellborecompletion.

[0022] Notwithstanding the above-described attempts at obtaining costeffective and workable lateral well completions, there continues to be aneed for new and improved methods and devices for providing suchcompletions, particularly sealing between the juncture of primary andlateral wells, the ability to re-enter lateral wells, particularly inmultilateral systems, and achieving zone isolation between respectivelateral wells in a multilateral well system. The present inventionrelates to a new and improved method and apparatus for the constructionand completion of a multilateral well junctions, and overcomes thedeficiencies of the prior art.

BRIEF SUMMARY OF THE INVENTION

[0023] A junction for the intersection of a main borehole and a lateralborehole includes a main tubular having a main window with a rampaligned with the main window, and a lateral tubular adapted to betelescopingly received within the main tubular and having a lateralwindow. The main tubular and lateral tubular each have an orientationsurface. The lateral tubular has a first position with one end partiallydisposed within the main tubular. The lateral tubular is telescoped intothe main tubular with the end of the lateral tubular engaging the rampwhich guides the end of the lateral tubular through the main window andinto the lateral bore. The orientation surfaces engage to orient thelateral window with the main window and form a common opening betweenthe tubulars. The ramp is preferably an arcuate surface at an angle tothe axis of the main tubular and extends along the edges of the mainwindow between the inner and outer diameters of the main tubular. Theorientation surfaces are preferably mule shoe surfaces which engage torotate the tubulars into alignment.

[0024] The junction may also include a shear member to releasablyconnect the lateral tubular within the main tubular until the junctionis to be deployed. Once the lateral tubular is released, preferably byshearing the shear member, it telescopes down into the main tubularuntil the lateral tubular reaches the ramp adjacent the main window. Theramp deflects the lateral tubular out through the main window byengaging the end of the lateral tubular. The lateral tubular has one endextending from the main tubular to form the junction between the lateralborehole and the primary borehole. The main tubular extends into themain borehole and the lateral tubular extends into the lateral borehole.

[0025] The present invention is also directed to a method ofmultilateral well completions. To create a lateral well bore, a millingassembly is run into the main well bore to a desired depth andorientation. An anchor and/or packer are set. If a well reference memberis not previously set, a reference member may also be set on the samerun. A window is milled in the cased borehole and a lateral rat hole isdrilled. The milling assembly and whipstock are then removed. Thejunction with main tubular and lateral tubular is run into the main borein substantial alignment. The lateral tubular is partially disposedwithin the main tubular and is releasably held by a shear member. Themain window becomes aligned with the lateral rat hole when an orientingmember at the bottom of the main tubular engages the downhole wellreference member, thereby rotating and orienting the junction assembly.

[0026] A weight is applied to the lateral tubular causing the lateraltubular to disengage the main tubular allowing the lateral tubular to bereceived within the main tubular. Any misalignment that occurs while thelateral tubular is deflected out of the main window via the ramp iscorrected when the lateral orientation member engages the orientationsurface of the main tubular. When the lateral orientation member and themain orientation surface are fully engaged, the lateral and main windowsare substantially aligned and facing each other to form the junction.

[0027] There are many benefits to using the present invention. Criticalwork is done prior to exposing the time dependent formations. A levelfour multilateral well can be achieved without milling excess liner. Aminimal amount of cementing is required, although cementing is optionalfor the present invention. The access diameters for both the main andlateral tubulars are maximized. The present invention allows re-entrycapabilities in both bores.

[0028] Other objects and advantages of the invention will appear fromthe following description.

BRIEF DESCRIPTION OF THE DRAWINGS

[0029] For a detailed description of the preferred embodiments of theinvention, reference will now be made to the accompanying drawings inwhich:

[0030]FIG. 1 is a schematic view of the deployed junction disposedwithin the main and lateral boreholes;

[0031]FIG. 2 is a side elevation view of the main tubular shown in FIG.1;

[0032]FIG. 3 is a front elevation view of the main tubular and mainwindow of FIG. 2;

[0033]FIG. 4 is a back view of the top portion of the main tubular ofFIG. 2;

[0034]FIG. 5A is a cross section view of the main tubular taken alongplane A-A of FIG. 2;

[0035]FIG. 5B is a cross section view of the main tubular taken alongplane B-B of FIG. 2;

[0036]FIG. 5C is a cross section view of the main tubular taken alongplane C-C of FIG. 3;

[0037]FIG. 5D is a cross section view of the main tubular taken alongplane D-D of FIG. 3;

[0038]FIG. 5E is a cross section view of the main tubular taken alongplane E-E of FIG. 3;

[0039]FIG. 6 is a side elevation view of the lateral tubular shown inFIG. 1;

[0040]FIG. 7 is a front elevation view of the lateral tubular andlateral window of FIG. 6;

[0041]FIG. 8 is an enlarged cross section view of the upper portion ofthe lateral tubular of FIG. 6;

[0042]FIG. 9 is a side elevation view of the main tubular of FIG. 2 withan orientation member disposed therein;

[0043]FIG. 10 is an enlarged view of the orientation member of FIG. 9;

[0044]FIG. 11A is a front elevation view of a deflector for use with thejunction of FIG. 1;

[0045]FIG. 11B is a front enlarged view of an orientation member coupledto the lower end of the deflector of FIG. 11A;

[0046]FIG. 12 is a side cross section view of the deflector of FIG. 11A;

[0047]FIG. 13A is a back elevation view of the deflector of FIG. 11A;

[0048]FIG. 13B is a back enlarged view of an orientation member coupledto the lower end of the deflector of FIG. 13A;

[0049]FIG. 13C is a cross section view of the orientation member anddeflector taken along plane C-C of FIG. 13B;

[0050]FIG. 13D is a cross section view of the orientation member anddeflector taken along plane D-D of FIG. 13B;

[0051]FIG. 14A is an enlarged view of the upper end of the deflector ofFIG. 12;

[0052]FIG. 14B is a cross section view of the deflector taken alongplane B-B of FIG. 12;

[0053]FIG. 14C is a cross section view of the deflector taken alongplane C-C of FIG. 12;

[0054]FIG. 14D is a cross section view of the deflector taken alongplane D-D of FIG. 13A;

[0055]FIG. 14E is a cross section view of the deflector taken alongplane E-E of FIG. 13A;

[0056]FIG. 15A is an elevation view of the whipstock assembly loweredinto the primary borehole;

[0057]FIG. 15B is an elevation view of the mills forming a window anddrilling a rat hole;

[0058]FIG. 15C is an elevation view of the mills having been retrievedand a drilling assembly having drilled a lateral borehole;

[0059]FIG. 15D is an elevation view of the whipstock assembly beingretrieved from the borehole;

[0060]FIG. 15E is an elevation view with the main tubular and lateraltubular being lowered into the main borehole in the undeployed coaxialposition;

[0061]FIG. 15F is an elevation view with the junction deployed at theintersection of the main borehole and lateral borehole;

[0062]FIG. 15G is an elevation view of a deflector disposed within themain tubular;

[0063]FIG. 15H is an elevation view a liner disposed through the lateraltubular and into the lateral borehole;

[0064]FIG. 16 is a side elevation view of an alternative lateral tubularwithout a main tubular;

[0065]FIG. 17 is a side elevation view of a well reference memberdisposed in the main cased borehole above the lateral borehole; and

[0066]FIG. 18 is a side elevation view of the lateral tubular of FIG. 16deployed in the lateral borehole of FIG. 17.

NOTATION AND NOMENCLATURE

[0067] Certain terms are used throughout the following description andclaims to refer to particular system components. This document does notintend to distinguish between components that differ in name but notfunction. In the following discussion and in the claims, the terms“including” and “comprising” are used in an open-ended fashion, and thusshould be interpreted to mean “including, but not limited to . . . ”.

[0068] The present invention relates to methods and apparatus forproviding a junction around a window cut in a casing and extending aliner into a lateral borehole. The present invention is susceptible toembodiments of different forms. There are shown in the drawings, andherein will be described in detail, specific embodiments of the presentinvention with the understanding that the present disclosure is to beconsidered an exemplification of the principles of the invention, and isnot intended to limit the invention to that illustrated and describedherein.

[0069] In particular, various embodiments of the present inventionprovide a number of different constructions and methods of operation. Itis to be fully recognized that the different teachings of theembodiments discussed below may be employed separately or in anysuitable combination to produce desired results. Reference to up or downwill be made for purposes of description with “up” or “upper” meaningtoward the surface of the well and “down” or “lower” meaning toward thebottom of the primary wellbore or lateral borehole.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0070] Referring initially to FIG. 1, a preferred embodiment of ajunction 10 is shown deployed to produce hydrocarbons from a pay zone 12through a primary borehole 14 and through a lateral borehole 16.Junction 10 includes a main tubular 20 and a lateral tubular 40 with themain tubular 20 extending into the primary borehole 14 and the lateraltubular 40 having its upper end disposed within an upper portion of themain tubular 20 and its lower end extending into the lateral borehole16. Lateral tubular 40 includes a window 42 aligned with a window 26 inmain tubular 20 in the deployed position whereby the production from payzone 12 through primary and lateral boreholes 14, 16 may be commingledfor flow to the surface 18.

[0071] Referring now to FIGS. 2-5, main tubular 20 includes a tubularbody 22 having an upwardly facing orientation surface 24 and a mainwindow 26 extending from an arcuate cut out 27 below orientation surface24 to a full tubular portion 28 near the lower end of main tubular 20.The inside diameter 31 in the upper portion of tubular body 22 is largerthan the inside diameter 33 in the lower portion of tubular body 22. Thelower terminal end 30 of tubular body 22 includes a counterbore 32forming a downwardly facing annular shoulder 34 for use with a deflectorhereinafter described. It should be appreciated that the lower terminalend 30 may include a threaded connection for connecting a spline subhereinafter described. Best shown in FIG. 4, orientation surface 24includes a pair of main cam surfaces 36 a,b forming a mule shoeextending from an apex 38 down into a recess or mule shoe slot 44.

[0072] Main window 26 includes a straight portion 46 and a ramp portion48. Straight portion 46 is an arcuate cross-sectional cut out in tubularbody 22 along the length of portion 46 having the enlarged innerdiameter 31.

[0073] Referring still to FIGS. 2-5, the ramp surface 50 is initiated atpoint 54 by milling arcuate ramp portion 58 with the inside diameter 31below the top of window 26 and continuing out the window 26 to point 54a. FIG. 5A is a cross section at point 56 of the arcuate ramp portion 58where it begins to intersect reduced diameter 33. The mill has milledthe arcuate portion 58 into the wall 60 of tubular body 22 and into theinner diameter of the wall 60 in the bottom face 64 of tubular body 22.FIG. 5B is a cross section showing the arcuate rails 62 a,b milled intothe wall 60 of tubular body 22 with the inner diameter of wall 60achieving reduced diameter 33. FIGS. 5C, D, E illustrate the arcuaterails 62 a,b milled into wall 60 in tubular body 22 along the lowerportions of ramp 50. As best shown in FIG. 3, the lower end of ramp 50is an arcuate milling at 66 in the outer surface of tubular body 22.

[0074] Ramp portion 48 is formed using a mill to cut a ramp surface 50in a method similar to that used in milling a whip face on a whipstock.The radius is cut on a taper like a whip face. It is not cut coaxiallywith tubular body 22 but at an angle to the axis of tubular 22. Incutting the ramp surface 50, the mill mills the tubular body 22 asthough it were a solid piece of metal such as in a whipstock. Thusinstead of milling an arcuate surface into a solid member, the arcuatesurface is milled into a tubular member. The taper of the ramp 50 may bebetween 1½ and 3° and is preferably 3°.

[0075] Referring now to FIGS. 6-8, lateral tubular 40 includes a tubularbody 68 having an orientation member 70, with a downwardly facingorientation surface 72, affixed, such as by welding, to the top oflateral tubular body 68, and a main window 42 extending from an arcuatecut out 74 below orientation surface 72 to a full tubular portion 76near the lower end of lateral tubular 40. The inner and outer diametersof lateral tubular body 68 are preferably uniform along its length.

[0076] Orientation member 70 is a tubular member which is received overthe upper end of lateral tubular body 68 and then preferably welded inplace. Downwardly facing orientation surface 72 includes a pair oflateral cam surfaces 84 a,b forming a mule shoe extending from a recessor mule shoe slot 86 down to an apex 88. Orientation member 70 ispreferably disposed on a separate member for ease of manufacture of thedownwardly facing orientation surface 72. Further, orientation member 70is a separate member to provide a connection 90 for a running tool.Connection 90 includes a counterbore 92 having a plurality of holes 94which engage latching members on the running tool. Connector 100includes a plurality of fingers 102 cut into the wall 95 of lateraltubular body 68. Fingers 102 have latch pads 104 attached to the freeend 106 of fingers 102, such as by screws 108.

[0077] Lateral window 42 is a precut window cut into lateral tubularbody 68. There is no radius cut for the window 42 in lateral tubular 40.The upper portion 110 of window 42 has straight sides 112 and the lowerportion of window 42 forms a hyperbolic portion 114. When lateral window42 is aligned with main window 26, the upper terminal end 116 of lateralwindow 42 is approximately adjacent point 54 on ramp 50 in main window26 and hyperbolic portion 114 is aligned with the lower hyperbolicportion 65 of main window 26. When in such alignment, facing windows 26,42 form a common opening 120, best shown in FIG. 1, between main tubular20 and lateral tubular 40 for the commingling of flow through the maintubular 20 from the primary borehole 14 and through lateral tubular 40from the lateral borehole 16. Windows 26, 42 serve to provide fullexposure of communication between main and lateral tubulars 20, 40.

[0078] The outer diameter of lateral tubular 40 is substantially thesame as the enlarged inner diameter 31 of main tubular 20 at the top ofmain tubular 20 to point 54, below the top of window 26, at which pointthe inner diameter 31 begins to decrease as previously described. Only asmall sliding clearance of about 0.060 of an inch is provided betweenmain tubular 20 and lateral tubular 40 above point 54.

[0079] In the assembled but not yet deployed position, the lower end 78of lateral tubular 40 is inserted into the upper end 25 of main tubular20 and main and lateral tubulars 20, 40 oriented such that mule shoepoint 38 on main tubular 20 is aligned with slot 86 on lateral tubular40. Likewise, apex 88 on lateral tubular 40 will be aligned with slot 44on main tubular 20. Since apex 88 is aligned with the centerline oflateral tubular window 42 and mule shoe point 38 is aligned with thecenterline of main tubular window 26, in this position, orientationsurfaces 24, 72 are now oriented such that windows 26, 42 face eachother.

[0080] Upon insertion and alignment, a shear pin 122 in the lower end oflateral tubular 40 is inserted into an aperture 124 in the upper end ofmain tubular 20 thereby attaching main and lateral tubulars 20, 40together for lowering into the primary borehole 14 from the surface 18.Preferably, the shear pin 122 is rated at 35,000 pounds. Shear screw 122prevents premature setting of lateral tubular 40 within main tubular 20should main tubular 20 encounter drag in the casing or become hung up inthe casing. The shear screw 122 also permits pushing the main tubular 20on the lower end of lateral tubular 40 through the borehole,particularly a horizontal borehole.

[0081] In another embodiment, the lateral tubular 40 may include aconnector like that of connector 100 to attach lateral tubular 40 to arecess in the upper end of main tubular 20 such as at 27. In thepreferred embodiment, should the shear pin 122 break prematurely, theconnector will maintain the main tubular 20 disposed on the lower end oflateral tubular 40.

[0082] In operation, the junction 10 is deployed by disposing the maintubular 20 on the lower end of lateral tubular 40 using shear pin 122. Arunning tool on the lower end of a work string is releasably attached tothe upper end of lateral tubular 40 by connection 90. This assembly islowered into the primary borehole 14 until the assembly engages a wellreference member, hereinafter described, which prevents the furtherdownward movement of the main tubular 20 within the primary borehole 14.Weight is placed on the assembly causing shear pin 122 to sheardisconnecting lateral tubular 40 from main tubular 20 and allowing thelateral tubular 40 to slide down into main tubular 20.

[0083] As the lower terminal end 78 of lateral tubular 40 moves throughthe top of main tubular 20, end 78 engages the beginning of ramp 50. End78 first rides up the ramp 50 beginning at point 54 and cams lateraltubular 40 outward through main window 26. At about point 56 end 78begins to ride the rails 62 a,b which are initially in the interiorwalls 60 of main tubular 20. Arcuate surfaces milled into main window 26of main tubular 20 form a ramp profile along the edges of window 26.This profile or ramp on the inner sides of main tubular 20 are cut intothe wall 60 of main tubular 20, thereby reducing its equivalent diameteras shown in FIGS. 2 and 5A-E. As best shown in FIG. 5, the opposingarcuate rails 62 a,b formed by the edges of open main window 26 thenengage and guide the lower end 78 of lateral tubular 40 out throughwindow 26.

[0084] Summarizing, the lower end 78 engages ramp 50, initially beingguided by a ramp from points 54 to 56, then the rails 62 a,b in theinner diameter of the walls 60 of main tubular 20 and then finally ridesup rails 62 a,b along the edges of window 26 and out through the lowerend of window 26. Thus the ramp 50 deflects the lower end 78 of lateraltubular 40 outwardly through main window 26. It should be appreciatedthat the lateral tubular 40 may have any predetermined length asrequired for the lateral borehole 16.

[0085] Referring again to FIG. 1, near the end of travel of the lateraltubular 40 through main tubular 20, apex 88 will engage orientationsurfaces 36 a,b and mule shoe point 38 will engage the orientationsurfaces 84 a,b. As apex 88 and mule shoe point 38 ride along theseorientation surfaces 36, 84, the lateral tubular 40 will rotate intoproper orientation with main tubular 20 thereby aligning lateral window42 with main window 26. Recess 44 shown in FIG. 4 receives apex 88 andrecess 86 receives mule shoe point 38. Recesses 44, 86 avoid theadditional expense of completing the contour of orientation surfaces 36,84.

[0086] As illustrated in FIG. 1, in the preferred embodiment, in thedeployed position, the lateral tubular 40 forms a Y junction with maintubular 20. Connector 100 connects lateral tubular 40 with main tubular20 by engaging end 27 on main tubular 20.

[0087] In an alternative embodiment, the inner diameter 31 of tubularbody 22 above and along the junction may be sized to receive twoconduits that may be sealed off inside the main tubular 20, such as whenthe production fluids from the primary borehole 14 and the lateralborehole 16 are from different pay zones. The two conduits extendthrough the upper portion of main tubular 20 with one conduit thenextending through main tubular 20 and the other independent conduitextending through lateral tubular 40. Additional clearance may beobtained through main tubular in reduced diameter 33 by increasing theinner diameter along the ramp 50 where the inner diameter is smaller.This can be achieved by scaling back the inner diameter portions betweenopposing arcuate rails 62 a,b. Thus rails 62 a,b remain intact while theportion of main tubular 20 remaining after milling window 26 can bereduced to enlarge inner diameters.

[0088] Referring now to FIGS. 9 and 10, another preferred embodiment ofthe present invention includes an orientation member 130 disposed in thelower end 30 of main tubular 20. The orientation member 130 includes atubular body having an upwardly facing orientation member or mule shoe134 used to orient subsequent tools lowered through the primary borehole14 below the junction with lateral borehole 16. The mule shoe 134 has areduced outer diameter 136 forming an upwardly facing annular shoulder138 which engages the lower terminal end 30 of main tubular 20. Uponorienting the mule shoe 134 with the window 26 and orientation surface24, orientation member 130 is welded to the lower end of main tubular 20at 140. The reduced outer diameter portion 136 includes a window orrecess 142 for receiving a latching engagement from a subsequently runtool to latch the tool in place within main tubular 20 and thus inorientation with lateral borehole 16. The lower end 144 may includethreads 146 for threading engagement to a lower tool such as a splinesub. Another method includes threading an extension sub having a muleshoe into the lower end of main tubular 20 and then orienting the muleshoe with respect to the window 26.

[0089] Referring now to FIGS. 11-14, there is shown one tool, namely adeflector 150, which may be used with orientation member 130 in maintubular 20 for directing other tools through the lateral tubular 40.Deflector 150 is used after lateral tubular 40 is deployed within maintubular 20. For instance, it may become necessary to re-enter thelateral borehole for further well operations such as for drilling thelateral borehole 16. Deflector 150 includes a tubular body 152 having alower connector or latch 154 with a plurality of collet finger slots156, best shown in FIGS. 14D and 14E, adapted to engage the orientationmember 130, and a ramp surface 160 extending from the upper terminal end158 to a point 162 approximately at the mid portion of tubular body 152.Moreover, deflector 150 also includes an internal bore 164 which allowsdownhole access to the main borehole 20 below the deflector 150.

[0090] Referring specifically to FIGS. 11B and 13B-D, it can be seenthat deflector 150 has a key, such as mule shoe 194, which engages themule shoe 134 of FIG. 10 to orient the deflector 150 with respect towindows 26 and 42. FIGS. 11B and 13B show the front and back views ofthe orientation member or mule shoe 194 which is coupled to the lowerend of the deflector 150 of FIGS. 11A, 12, and 13A. Also shown are thecollet fingers 157 of latch 154 which work in conjunction with colletslots 156 to engage orientation member 130. Shear screws 161 releasablyattach collet fingers 157 and mule shoe 194 to the lower end ofdeflector 150. When it is necessary to retrieve deflector 150, thescrews 161 may be sheared by an upward force exerted on deflector 150,thereby separating deflector 150 from both mule shoe 194 and colletfingers 157.

[0091] A recess 170 is provided through the upper end of ramp surface160 for connection to a retrieving tool to retrieve deflector 150.Recess 170 includes a retrievable hook slot 172 which is used as astandard method of retrieval for a deflector. Upon lifting theretrieving tool, the deflector 150 is also lifted from within maintubular 20.

[0092] Deflector ramp surface 160 begins at the initial cam surface 166on upper terminal end 158, best shown in FIG. 14A. The ramp surface 160extends past an upset 168 on tubular body 152 to mid point 162. SeeFIGS. 14B and 14C. Ramp surface 160 is formed similarly to ramp surface50 of main tubular 20. Ramp surface 160 is spaced from orientationmember 130 such that tools passing down the upper portion of main andlateral tubulars 20, 40 are directed by ramp 160 out through the lateraltubular 40 and into the lateral borehole 16.

[0093] In operation, the deflector 150 is lowered from the surface 18down through the cased borehole and into the main tubular 20. A key,such as mule shoe 194 on the lower end of deflector 150, engages themule shoe 134 on orientation member 130. The mule shoe 134 oforientation member 130 in main tubular 20 is used to land and orientdeflector 150. As deflector 150 reaches slot 142, the collet connector154 on the lower end of deflector 150 latches onto the orientationmember 130.

[0094] In an alternative embodiment, a sealing assembly may be attachedto the lower end of deflector 150 such that the sealing assembly sealsor isolates primary borehole 14. A sealing assembly on deflector 150 isoptional.

[0095] In another embodiment the deflector is eliminated and ramp 50 isused to deflect subsequent tools being passed through the junction. Themain tubular bore size is reduced along the ramp 50 and below thejunction. Machining a smaller bore in main tubular 20 causes the walls60 to be wider. This will allow the ramp 50 in the bottom of maintubular 20 to serve both the purpose of deploying lateral tubular 40 andto serve the function of a deflector in deflecting tools out into thelateral borehole 16. However, it is necessary that the bore through themain tubular 20 be reduced.

[0096] Once junction 10 is in place, no tool can be run down throughjunction 10 which is larger than the inner diameter of the lateraltubular 40. In one size of the preferred embodiment, lateral tubular 40has an inner diameter of about 6½ inches. Thus, a subsequent tool orother member which is 6½ inches in outside diameter could pass downthrough the main tubular 20 because it will clear the ramp. However,nothing requires that the bore through the main tubular 20 below thelateral tubular 40 be 6½ inches in inside diameter. It could be smaller,such as 6 inches. Thus, if a tool 6½ inches in diameter is run downhole, it could not pass through main tubular 20 at the junction. Itwould be deflected out into the lateral borehole.

[0097] Referring now to FIGS. 15A-H, there is shown the sequential stepsof a preferred method using the junction 10 of the present invention.Referring to FIG. 15A, a one trip milling assembly 200 is lowered intocased primary borehole 14 on a work string 202. The one trip millingassembly 200 includes a reentry tool 204, a spline sub 206, aretrievable anchor 208, a debris barrier 210, a production packer 212, awhipstock 214 having a ramp 216, and one or more mills 218, 220releasably attached at 222 to the upper end of whipstock 214. The mills218, 220 are disposed on the end of the work string 202 extending to thesurface 18. The one trip milling assembly 200 is lowered onto a wellreference member 230 which may be previously installed at apredetermined location in the cased primary borehole 14 for subsequentwell operations, such as milling a window 240 in the casing 224 ofprimary borehole 14. Well reference member 230 may be termed an insertlocator device (ILD) which replaces the typical big bore packer. Wellreference member 230 is shown and described in pending U.S. PCTApplication Serial No. PCT/JUS01/16442 filed May 18, 2001, herebyincorporated herein by reference.

[0098] Reentry tool 204 is mounted on spline sub 206 and includes adownwardly facing mule shoe 232 for engagement with upwardly facing muleshoe 234 on well reference member 230.

[0099] Well reference member 230 locates and orients the one tripmilling assembly 200 above it. Well reference member 230 neither servesas an anchor member nor as a sealing member; it merely provides depthlocation and orientation for subsequent well operations over the life ofthe well. The anchoring and sealing functions are performed by othertools in the assembly 200 such as retrievable anchor 208 and productionpacker 212, which may be a weight set production packer. The assembly200 is set down on the well reference member 230 and then weight isapplied to the work string 202. The well reference member 230 orientsthe ramp 216 of whipstock 214 in the preferred direction of the windowto be milled in the casing 224 shown in FIG. 15B. After anchor 208 isset, the work string 202 is pulled or pushed causing the lead mill 218to shear connection 222 at the upper end of whipstock 214. Mills 218,220 are then rotated and guided by whipstock ramp 216 into the casing224 as work string 202 rotates the mills causing them to mill a windowin casing 224.

[0100] Referring now to FIG. 15B, mill 218 is shown milling through themain bore casing 224 to form a window 240. The window 240 is milledusing conventional milling techniques. The use and configuration ofthese components in milling operations is well known by those skilled inthe art. The work string 202 is rotated, thereby rotating mills 218, 220as mills 218, 220 move downwardly and outwardly on ramp 216 of whipstock214. Ramp 216 guides the rotating mills 218, 220 into engagement withthe casing 224, thus cutting window 240 in casing 224. The mills 218,220 continue to drill a rat hole 226, as the beginning of the lateralborehole 16, best shown in FIG. 15C.

[0101] Referring now to FIG. 15C, once the rat hole 226 has been drilledusing mills 218, 220, the work string 202 and mills 218, 220 areretrieved and removed from the cased primary borehole 14. A drill string(not shown) then is lowered into primary borehole 14 engaging the rampsurface 216 of whipstock 214 to enter rat hole 226 to drill the lateralborehole 16. Once the lateral borehole 16 has been completed, the drillstring is removed from the cased borehole 14 and retrieved to thesurface 18.

[0102] Referring now to FIG. 15D, upon completing the drilling of thelateral borehole 16, a whipstock retrieval tool 228 is lowered andconnected to the upper end of whipstock 214. The retrievable anchor 208is released from the cased borehole 14 and the whipstock assembly 200 isretrieved from the well. Everything but the well reference member 230then has been removed from the main wellbore 14.

[0103] Referring now to FIG. 15E, the junction 10 is in a runningconfiguration and is attached to a running tool 238 on the lower end ofanother work string 202 by releasably connecting running tool 238 toconnection 90 on the upper end of lateral tubular 40. Running tool 238attaches to the upper end of lateral tubular 40 just above orientationmember 72. Shear screws fit into apertures 94 to attach running tool 238to the upper end of lateral tubular 40.

[0104] The lower end of lateral tubular 40 is inserted into the upperend of main tubular 20 and attached by shear pin 122. A reentryorientation tool 242 is attached to the lower end 30 of the main tubular20. The reentry orientation tool 242 includes a downwardly facing muleshoe 244 which engages the upwardly facing mule shoe 234 on wellreference member 230 to cam the entire junction assembly of tubulars 20,40 into the proper orientation with respect to the window 240 which hasbeen milled into the casing of the cased borehole 14. In the preferredembodiment, the reentry orientation tool 242 may or may not latch ontothe well reference member 230. A spline sub 206 is located just belowmain tubular 20 and is used to properly orient the mule shoe 244 ofreentry tool 242 such that when the assembly is landed onto the wellreference member 230, the junction assembly is properly oriented withrespect to the window 240 in casing 224. The spline sub 206 allows thereentry orientation tool 242 to be realigned in 5° increments thus,providing 72 different positions.

[0105] Referring now to FIG. 15F, junction 10 is shown in the deployedposition. After the junction 10 has been oriented with casing window240, weight is applied to the junction assembly so as to shear the shearpin 122. Since main tubular 20 has landed and can no longer move furtherdown into the main bore 14, the weight causes lateral tubular 40 to movedownwardly within the main tubular 20 whereupon the lateral tubularengages the ramp 50 of main tubular 20. As lateral tubular 40 continuesits downward movement, ramp 50 cams lateral tubular 40 out through mainwindow 26 and into the lateral borehole 16. As the lateral tubular 40moves through the main window 26, the downwardly facing lateral tubularmule shoe 72 engages the upwardly facing mule shoe 24 on main tubular 20causing lateral.tubular 40 to rotate into alignment with main tubular 20whereby the windows 26, 42 are aligned forming a common window 120 and aY junction between primary borehole 14 and lateral borehole 16.

[0106] Referring now to FIG. 15G, deflector 150 may be lowered into themain tubular 20 using a deflector running tool on a work string. Themule shoe 194 on the lower end of deflector 150 engages the upwardlyfacing mule shoe 134 on orientation member 130 to properly orientdeflector 150 so that ramp surface 160 of deflector 150 faces the casingwindow 240 and lateral bore 16.

[0107] Referring now to FIG. 15H, having deployed junction 10, a liner246 may be run through the lateral tubular 40 and into the lateral bore16. The liner 246 may or may not be used in the present invention and isan alternative embodiment.

[0108] The junction 10 as shown in FIG. 15H is a level three because thejunction 10 includes a first tubular 20 extending into the main borehole14 and a second tubular 40 extending into the lateral borehole 16without cementing or sealing the junction. A level four can be achievedby cementing in junction 10. To cement junction 10, packers or plugs areset in primary borehole 14 below main tubular 20 and then a flappervalve is set above the orientation member 130 to prevent cement fromreaching upwardly facing mule shoe 134. A clean out tool is then runthrough the main tubular 20 to just above orientation member 130 toremove the cement in main tubular 20 and through the lateral tubular 40to remove the cement in lateral tubular 40. Thus a level four junctionhas been achieved.

[0109] A level five may be achieved by running a pair of conduits intothe junction 10 with each conduit having a packer or other sealingassembly on its lower end. A dual bore packer is attached to the upperends of the conduits. One conduit is run into the main tubular 20 andits packer set to seal with the cased borehole below the main tubular 20and the other conduit is run into the lateral tubular 40 and its packeris set below the lateral tubular 40 in the lateral borehole 16. The dualbore packer is set above the junction 10 in the cased primary boreholeabove the junction 10. The sealing engagements of the packers providesthe required pressure integrity at the junction for a level five.

[0110] In another alternative embodiment of this invention, the maintubular 20 and lateral tubular 40 can be run separately into the wellbore. This is typically necessary when the lateral tubular 40 includes apipe string that is hundreds of feet long. Usually, the lateral 40 isrun as one piece with the main tubular 20, but when it is so long thatthe lateral tubular 40 extends a great distance into the lateralborehole 16, it becomes impractical to run the assembly as one piece. Insuch an embodiment, the lateral tubular 40 can be run in separatelyafter the main tubular 20 has landed onto the well reference member 230.After the main tubular 20 is run into the main bore 14, the main window26 is aligned with the casing window 240. The lateral tubular 40 maysubsequently be run through the main bore 14 and into the lateral bore16, similarly achieving alignment between the main window 26 and lateralwindow 42.

[0111] Where a long pipe string is attached to the end of the maintubular 20, a retainer may be added to the lower end of lateral tubular40 adjacent the shear pin 122 to carry the additional load of the maintubular 20 on the lateral tubular 40. Also if a liner is attached to theend of lateral tubular 40, a swivel may be used to attach the lateraltubular 40 with the liner to allow the liner to swivel freely as theliner is passing into the lateral borehole 16.

[0112] One advantage of the present invention is that a liner severalhundred feet long can be disposed on the end of the lateral tubular 40and run immediately after the borehole has been drilled. This providessupport for any unconsolidated formation in the lateral borehole 16within hours of drilling the borehole 16. For example, if a 300 footlong lateral borehole 16 is drilled, it is preferred to insert a linerinto the 300 foot lateral borehole 16 using the end of the lateraltubular 40 right after drilling the 300 foot lateral borehole 16.Although it may be preferred in the prior art to drill the borehole, setthe liner, cement the liner off, and then drill out the end of the linerin the lateral tubular, this takes much longer and poses a problem withunconsolidated formation which may cave into the lateral borehole 16before the complete borehole is drilled and the liner installed. Oncethe 300 foot liner has been installed, then the remainder of the lateralborehole 16 can be drilled through the liner.

[0113] Referring now to FIGS. 16-18, in still another embodiment, a wellreference member 230, like that shown in pending U.S. PCT ApplicationSerial No. PCT/JUS01/16442, is disposed in the casing 224 of primaryborehole 14 above the drilled lateral borehole 16. This embodiment isdescribed in Great Britain Application No. U.K. 0112456.9, filed on May22, 2001, and entitled “Downhole Lateral Completion System,” herebyincorporated by reference. In this embodiment the well reference member230 is located above the junction rather than below as in previousembodiments. Well reference member 230 is set after the lateral borehole16 is drilled. As shown in FIGS. 16-17, well reference member 230 servesas the orienting member for the lateral tubular 250, similar to lateraltubular 40, which is lowered individually down the primary casedborehole 14 without a main tubular 20. As shown in FIG. 16, the lateraltubular 250 includes a mating orienting member 252, such as a matingmule shoe, which engages well reference member 230 for orienting thewindow 254 in lateral tubular 250 with the window 240 of the lateralborehole 16. A deflector may be set below the junction to guide thecompletion into the lateral borehole 16. As shown in FIG. 18, productionthrough the main borehole 14 passes through the cased borehole below thejunction since there is no main tubular.

[0114] In a further embodiment, the junction may be used in a new wellwhere the operator knows that a lateral borehole 16 is to be drilled.The main tubular 20 may be run as part of a casing string. The ends ofmain tubular 20 have threaded connections so that it could be attachedto a length of casing. In one example, the main tubular 20 is run aspart of a 9⅝ inch string of casing whereby the inside diameter of top ofthe main tubular 20 may be 8½ inches, allowing a larger ramp out anglethrough window 26. Also larger sized tubulars may be run through maintubular 20. Window 26 in main tubular 20 is scabbed over by a sleevewhich fits over the outside of main tubular 20 to protect and close offwindow 26. The sleeve may be a fiberglass sheath. The sleeve over window26 permits the casing 224 to be cemented in the borehole 14 without thecement flowing through window 26 and into the inside diameter of maintubular 20.

[0115] Once the main tubular 20 has been cemented in place, the maintubular 20 is then cleaned and the sleeve milled out to expose thewindow 26 such that the lateral borehole 16 can be drilled throughwindow 26. A deflector 150 may be lowered into the main tubular 20 toguide a tool to drill out the fiberglass sheath. The lateral tubular 40may then subsequently be run down through main tubular 20 and ramped outinto the newly drilled lateral borehole 16. This is basically a sectionof casing with a pre-milled window. Pre-milled windows are taught by theprior art, thus one with skill in the art can appreciate a pre-milledwindow scabbed over by a sheath. However, the prior art casings withpre-milled windows do not include ramps to guide an inner member outinto the lateral borehole 16.

[0116] In this alternative embodiment, the window 26 must be oriented inthe proper direction since it is more difficult to rotate and align astring of casing. Preferably there is also included a mule shoe profilein the main tubular 20 to properly orient the subsequent lateral tubular40 so that it is deployed out into a subsequently produced lateralborehole. Thus, there may be a profile, either above or below window 26to guide, land, and orient the lateral tubular 40 which is subsequentlyrun into the well. In one embodiment, the profile is above the window,as was seen in the embodiment of FIGS. 16-18 on Great BritainApplication No. U.K. 0112456.9. However, the profile may be disposedinside the main tubular 20 causing the flowbore of the casing string tobe reduced.

[0117] The mule shoe may be part of the main tubular 20 if the alignmentof the window 26 with the lateral borehole 16 is known. The wellreference member 230 is used in the preferred embodiment to align theentire assembly. If a well reference member is also included in thisembodiment, little advantage has been gained. However, severaladvantages do emerge in this embodiment. One advantage is that thewindow 26 has been pre-cut and will not have to be milled, thus theoperator knows the exact profile of the window 26. When a window ismilled into the casing, the edges of the window in the casing are jaggedand unpredictable, and therefore hard to seal. Another advantage is thatthe mule shoe could also be pre-milled inside the main tubular in thecasing string. The mule shoe is then set for depth and orientation. Thethroughbore may be slightly larger in the alternative embodiment than inthe preferred embodiment, but not so much larger as to encourageincluding the main tubular 20 in the casing string rather than runningit in later with the lateral tubular 40.

[0118] The above discussion is meant to be illustrative of theprinciples and various embodiments of the present invention. Numerousvariations and modifications will become apparent to those skilled inthe art once the above disclosure is fully appreciated. It is intendedthat the following claims be interpreted to embrace all such variationsand modifications.

What is claimed is:
 1. An apparatus comprising: a tubular boreholecasing having an inner surface and a casing aperture in one sidethereof; a tubular having a cylindrical portion with an opening in oneside thereof; an orienting member disposed on said inner casing surfaceabove said casing aperture; and wherein said tubular has a firstposition with said casing and said tubular being coaxial and a secondposition with said tubular engaged with said orienting device, saidtubular opening substantially aligned with said casing aperture and saidtubular cammed out said casing aperture with one end of said tubularprojecting from said casing aperture.
 2. The apparatus of claim 1wherein said casing aperture and tubular opening form a common windowbetween said casing and tubular.
 3. The apparatus of claim 1 whereinsaid tubular further includes an orienting member disposed on an outersurface of said tubular cylindrical portion above said tubular opening,wherein said tubular orienting member is configured to mate with saidcasing orienting member.
 4. The apparatus of claim 1 further comprisinga deflector disposed inside said borehole casing below said casingaperture.
 5. The apparatus of claim 1 wherein said casing aperture formsopposing edges providing a ramp adjacent said casing aperture.
 6. Theapparatus of claim 4 wherein said ramp includes an arcuate surface cutat an angle in said tubular.
 7. A method of deploying a Y junction, themethod comprising: pre-milling an aperture in a portion of boreholecasing, said aperture forming opposing edges providing a guide surfaceadjacent said aperture; inserting one end of a tubular into saidborehole casing portion; further inserting said tubular into said casingportion against said guide surface in said casing portion; guiding saidone end of said tubular along said guide surface through said casingaperture; and extending said one end of said tubular through saidaperture with another end of said tubular remaining in said casingportion to form a Y junction.
 8. A method of deploying a Y junction, themethod comprising: inserting one end of a tubular into a borehole casingportion, said casing portion having an aperture in one side thereof andsaid tubular having an opening in one side thereof; further insertingsaid tubular into said casing portion toward said aperture; camming saidone end of said tubular through said aperture; orienting said tubularand said casing portion using cooperative orientation surfaces on saidtubular and said casing portion such that said opening and said aperturealign with each other; extending said one end of said tubular throughsaid aperture with another end of said tubular remaining in said casingportion; and mating said orientation surfaces to form a Y junctionwherein said opening and said aperture form a common window.